2019 integrated resource plan (irp) public input meeting april … · next steps analysis 3 •...
TRANSCRIPT
2019 Integrated Resource Plan (IRP) Public Input Meeting
April 25, 2019
1
Summary
2
• Updated coal-retirement cases account for incremental resource costs to address reliability issues identified and discussed at the December 2018 public-input meeting.
• The updated analysis shows there are potential customer benefits from accelerating the retirement of certain coal units—the greatest customer benefits are associated with an accelerated retirement of certain units at the Naughton and Jim Bridger power plants.
• The results of these studies do not reflect a final least-cost, least-risk plan.
• Additional resource portfolio analysis will be completed in the coming months before PacifiCorp finalizes the 2019 IRP, which it plans to file with state commissions by August 1, 2019.
Next Steps Analysis
3
• Additional analysis necessary to establish a preferred portfolio will include, but not limited to:
• Alternative operational scenarios for existing coal units (i.e., gas conversion, reduced operating minimums, and seasonal operations).
• Assessment of implementation and resource adequacy risk, employee and community transitions (i.e. staging of potential early coal retirements).
• Risk assessment of near-term replacement resources.
• Energy Gateway transmission cases.
• Assessment of expected schedules to implement a request-for-proposals process consistent with new legislation in Wyoming and potential interactions with state-driven new resource procurement rules.
• Regional haze compliance alternatives.
• Market price and CO2 policy scenario risk assessment (price-policy scenarios).
Updated Benchmark Case
4
(5,000)
0
5,000
10,000
15,000
20
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Renewable and Storage
Wind Solar Wind+Bat Solar+Bat Battery Pumped Storage Renewable Removed
0
1,000
2,000
3,000
20
19
20
20
20
21
20
22
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Demand-Side Management
Class 2 DSM Class 1 DSM
(5,000)
(4,000)
(3,000)
(2,000)
(1,000)
0
20
19
20
20
20
21
20
22
20
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Coal
Coal Removed
(1,000)
(500)
0
500
1,000
1,500
20
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21
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22
20
23
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24
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Gas
Gas Peaker Gas CCCT Gas Removed
0
500
1,000
1,500
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19
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20
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24
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25
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26
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Summer FOTs
FOT
Benchmark Case (C-01) Resource Portfolio
5
Resource Type 2038 Nameplate Capacity
Net Wind 2,485
Net Solar 3,864
New Battery 3,211
New Class 1 DSM 402
New Class 2 DSM 2,191
Net Gas 757
Net Coal (4,337)
Benchmark Case (C-01)Transmission Upgrades
6 *Note, capital is applied in the model reflecting real-levelized revenue requirement based on 88% of the nominal capital shown in the table above. The 12% reduction to capital is applied to capture assumed third-party revenue credits via the OATT formula rate.
Year Resource Location From To ATC Max Interconnection Nominal Capital ($m)
2021 UT South UT South UT South 0 300 $8.0
2025 Yakima WA Yakima WA Yakima WA 0 405 $3.1
2025 Southern OR Southern OR Southern OR 0 975 $85.2
2025 SW WY SW WY SW WY 0 100 $8.8
2026 UT South UT South UT South 0 800 $188.0
2030 Goshen ID Goshen ID UT North 800 800 $253.7
2032 Aeolus Aeolus UT South 1,500 1500 $2,319.2
2033 Walla Walla WA Walla Walla WA Yakima WA 200 450 $74.8
2037 Yakima WA Yakima WA Southern OR 450 835 $260.7
2037 UT North UT North UT North 0 500 $50.9
2037 SW WY SW WY SW WY 0 500 $38.8
Total $3,294.6
• Yakima WA to Southern OR in 2037 is an expansion of the Yakima upgrade in 2025
Stacked-Retirement Summary Results
7
Stacked-Retirement CasesPVRR(d) Results
8 *Note: in all cases it is assumed that Naughton 3 (280 MW) is retired in 2019 and that Cholla 4 (387 MW) is retired at the end of 2020—however, these units are retired in the benchmark case and therefore not incremental to the stacked-retirement cases listed above.
Case
Inc. Retired
Capacity in
2023 (MW)
PVRR(d)
(Benefit)/Cost
of Early
Retirement
($m) Naughton 1 Naughton 2 Bridger 1 Bridger 2 Hayden 1 Hayden 2 Craig 1 Craig 2
Dave
Johnston 3
C-34 357 ($123)
C-35 711 ($211)
C-36 510 ($158)
C-37 554 ($143)
C-38 755 ($120)
C-39 834 ($52)
C-40 1,193 ($191)
C-41 1,529 ($12)
C-42 1,063 ($248)
C-43 928 ($31)
Stacked Cases C-34 and C-35
9
• The nominal levelized cost of the retired coal resources is $29.33/MWh higher than the nominal levelized costs of the portfolio of replacement resources.
• CO2 emission cost savings account for 18.6% of the overall benefit associated with accelerated retirement.
• Run-rate fixed costs would need to drop by 59.8% to achieve break-even economics with the replacement portfolio.
Case C-34 (NT1-2)
• The nominal levelized cost of retired coal resources is $20.71/MWh higher than the nominal levelized costs of the portfolio of replacement resources.
• CO2 emission cost savings account for 45.9% of the overall benefit associated with accelerated retirement.
• Run-rate fixed costs would need to drop by 37.0% to achieve break-even economics with the replacement portfolio.
Case C-35 (NT1-2, JB1)
(200)
(150)
(100)
(50)
0
50
100
150
Avg
MW
Average Annual Capacity of Replacement Resources and Levelized Costs Relative to Retired Coal
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas Peaker
Gas CCCT Class 2 DSM Class 1 DSM FOT
$61 $90
Nominal Levelized Cost ($/MWh)(600)
(400)
(200)
0
200
400
Avg
MW
Average Annual Capacity of Replacement Resources and Levelized Costs Relative to Retired Coal
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas Peaker
Gas CCCT Class 2 DSM Class 1 DSM FOT
$81 $102
Nominal Levelized Cost ($/MWh)
Stacked Cases C-36 and C-37
10
• The nominal levelized cost of retired coal resources is $19.15/MWh higher than the nominal levelized costs of the portfolio of replacement resources.
• CO2 emission cost savings account for 61.9% of the overall benefit associated with accelerated retirement.
• Run-rate fixed costs would need to drop by 34.2% to achieve break-even economics with the replacement portfolio.
Case C-36 (NT1, JB1) Case C-37 (NT1, JB1, HY1)
• The nominal levelized cost of retired coal resources is $16.00/MWh higher than the nominal levelized costs of the portfolio of replacement resources.
• CO2 emission cost savings account for 72.4% of the overall benefit associated with accelerated retirement.
• Run-rate fixed costs would need to drop by 29.1% to achieve break-even economics with the replacement portfolio.
(600)
(400)
(200)
0
200
400
Avg
MW
Average Annual Capacity of Replacement Resources and Levelized Costs Relative to Retired Coal
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas Peaker
Gas CCCT Class 2 DSM Class 1 DSM FOT
$83 $102
Nominal Levelized Cost ($/MWh)(600)
(400)
(200)
0
200
400
Avg
MW
Average Annual Capacity of Replacement Resources and Levelized Costs Relative to Retired Coal
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas Peaker
Gas CCCT Class 2 DSM Class 1 DSM FOT
$85 $101
Nominal Levelized Cost ($/MWh)
Stacked Cases C-38 and C-39
11
• The nominal levelized cost of retired coal resources is $11.03/MWh higher than the nominal levelized costs of the portfolio of replacement resources.
• CO2 emission cost savings account for 96.0% of the overall benefit associated with accelerated retirement.
• Run-rate fixed costs would need to drop by 20.0% to achieve break-even economics with the replacement portfolio.
Case C-38 (NT1-2, JB1, HY1) Case C-39 (NT1-2, JB1, HY1, CG2)
• The nominal levelized cost of retired coal resources is $3.67/MWh higher than the nominal levelized costs of the portfolio of replacement resources.
• CO2 emission cost savings account for 346.9% of the overall benefit associated with accelerated retirement.
• Run-rate fixed costs would need to drop by 7.6% to achieve break-even economics with the replacement portfolio.
(600)
(400)
(200)
0
200
400
Avg
MW
Average Annual Capacity of Replacement Resources and Levelized Costs Relative to Retired Coal
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas Peaker
Gas CCCT Class 2 DSM Class 1 DSM FOT
$90 $101
Nominal Levelized Cost ($/MWh)(800)
(600)
(400)
(200)
0
200
400
Avg
MW
Average Annual Capacity of Replacement Resources and Levelized Costs Relative to Retired Coal
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas Peaker
Gas CCCT Class 2 DSM Class 1 DSM FOT
$89 $93
Nominal Levelized Cost ($/MWh)
Stacked Cases C-40 and C-41
12
• The nominal levelized cost of retired coal resources is $8.94/MWh higher than the nominal levelized costs of the portfolio of replacement resources.
• CO2 emission cost savings account for 132.4% of the overall benefit associated with accelerated retirement.
• Run-rate fixed costs would need to drop by 18.1% to achieve break-even economics with the replacement portfolio.
Case C-40 (NT1-2, JB1-2, HY1, CG2) Case C-41 (NT1-2, JB1-2, HY1-2, CG1-2, DJ3)
• The nominal levelized cost of retired coal resources is $0.43/MWh higher than the nominal levelized costs of the portfolio of replacement resources.
• CO2 emission cost savings account for 2,525.4% of the overall benefit associated with accelerated retirement.
• Run-rate fixed costs would need to drop by 1.0% to achieve break-even economics with the replacement portfolio.
(1,000)
(500)
0
500
Avg
MW
Average Annual Capacity of Replacement Resources and Levelized Costs Relative to Retired Coal
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas Peaker
Gas CCCT Class 2 DSM Class 1 DSM FOT
$84 $93
Nominal Levelized Cost ($/MWh)(1,500)
(1,000)
(500)
0
500
1,000
Avg
MW
Average Annual Capacity of Replacement Resources and Levelized Costs Relative to Retired Coal
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas Peaker
Gas CCCT Class 2 DSM Class 1 DSM FOT
$80 $80
Nominal Levelized Cost ($/MWh)
Stacked Cases C-42 and C-43
13
• The nominal levelized cost of retired coal resources is $14.21/MWh higher than the nominal levelized costs of the portfolio of replacement resources.
• CO2 emission cost savings account for 77.0% of the overall benefit associated with accelerated retirement.
• Run-rate fixed costs would need to drop by 26.3% to achieve break-even economics with the replacement portfolio.
Case C-42 (NT1-2, JB1-2) Case C-43 (NT1-2, JB1, DJ3)
• The nominal levelized cost of retired coal resources is $1.97/MWh higher than the nominal levelized costs of the portfolio of replacement resources.
• CO2 emission cost savings account for 432.0% of the overall benefit associated with accelerated retirement.
• Run-rate fixed costs would need to drop by 4.8% to achieve break-even economics with the replacement portfolio.
(1,000)
(800)
(600)
(400)
(200)
0
200
400
Avg
MW
Average Annual Capacity of Replacement Resources and Levelized Costs Relative to Retired Coal
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas Peaker
Gas CCCT Class 2 DSM Class 1 DSM FOT
$84 $99
Nominal Levelized Cost ($/MWh)(600)
(400)
(200)
0
200
400
Avg
MW
Average Annual Capacity of Replacement Resources and Levelized Costs Relative to Retired Coal
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas Peaker
Gas CCCT Class 2 DSM Class 1 DSM FOT
$77 $79
Nominal Levelized Cost ($/MWh)
Stacked-Retirement Detailed Results
14
Stacked Case C-34 Overview (NT1-2)
15
($140)
($120)
($100)
($80)
($60)
($40)
($20)
$0
$20
$40
$60
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
$ m
illio
n
Change in System Costs (Base/Base Price-Policy)
Net (Benefit)/Cost Cumulative PVRR(d)
• No change in network transmission upgrades associated with changes to proxy resources in the portfolio relative to the Benchmark Case.
(600)(400)(200)
0200400600800
1,000
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
Cu
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Increase/(Decrease) in Nameplate Capacity with Assumed Retirement
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas
Class 1 DSM Class 2 DSM FOT
Stacked Case C-34 Detail(NT1-2)
16
StudyPVRR(d) (Benefit)/Cost of 2022 Retirement
($m)
Nom. Lev. (Benefit)/Cost of 2022 Retirement per MWh of Retired Generation
($/MWh)
Cost Savings from Retired Unit
Fuel ($138) ($32.87)
Inc. Capital Rev. Req. and Fixed O&M ($206) ($49.06)
Variable O&M $0 $0.00
Emissions ($42) ($9.95)
Decommissioning $8 $1.82
Total Net Cost Savings from Retired Unit ($378) ($90.07)
Net Replacement Costs
Fuel $145 $34.42
Inc. Capital Rev. Req. and Fixed O&M $124 $29.58
Variable O&M $18 $4.21
Emissions $19 $4.49
Demand-Side Management ($71) ($16.82)
Long-Term Contracts $2 $0.59
Market Purchases $10 $2.34
Market Sales $7 $1.76
Reserve/Energy Deficiencies $1 $0.18
Transmission Upgrades $0 $0.00
Transmission Reinforcements $0 $0.00
Total Net Replacement Cost $255 $60.74
Net (Benefit)/Cost of Assumed Early Retirement ($123) ($29.33)
Stacked Case C-35 Overview (NT1-2, JB1)
17
Change in Transmission Upgrades
Change in Year Resource Location From To ATC Max InterconnectionChange in Nominal
Capital ($m)
Accelerated from 2033 to 2032
Walla Walla WA Walla Walla WA Yakima WA 200 450 ($1.7)
Total ($1.7)
($250)
($200)
($150)
($100)
($50)
$0
$50
$100
$150
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
$ m
illio
n
Change in System Costs (Base/Base Price-Policy)
Net (Benefit)/Cost Cumulative PVRR(d)
(1,500)
(1,000)
(500)
0
500
1,000
1,500
2,000
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
Cu
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W
Increase/(Decrease) in Nameplate Capacity with Assumed Retirement
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas
Class 1 DSM Class 2 DSM FOT
Stacked Case C-35 Detail(NT1-2, JB1)
18
StudyPVRR(d) (Benefit)/Cost of 2022 Retirement
($m)
Nom. Lev. (Benefit)/Cost of 2022 Retirement per MWh of Retired Generation
($/MWh)
Cost Savings from Retired Unit
Fuel ($334) ($32.81)
Inc. Capital Rev. Req. and Fixed O&M ($569) ($55.92)
Variable O&M ($3) ($0.28)
Emissions ($143) ($14.01)
Decommissioning $13 $1.27
Total Net Cost Savings from Retired Unit ($1,035) ($101.76)
Net Replacement Costs
Fuel $265 $26.07
Inc. Capital Rev. Req. and Fixed O&M $353 $34.74
Variable O&M $17 $1.67
Emissions $46 $4.51
Demand-Side Management ($39) ($3.88)
Long-Term Contracts $38 $3.78
Market Purchases $70 $6.84
Market Sales $68 $6.64
Reserve/Energy Deficiencies $5 $0.53
Transmission Upgrades $2 $0.15
Transmission Reinforcements $0 $0.00
Total Net Replacement Cost $824 $81.05
Net (Benefit)/Cost of Assumed Early Retirement ($211) ($20.71)
Stacked Case C-36 Overview (NT1, JB1)
19
($200)
($150)
($100)
($50)
$0
$50
$100
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
$ m
illio
n
Change in System Costs (Base/Base Price-Policy)
Net (Benefit)/Cost Cumulative PVRR(d)
• No change in network transmission upgrades associated with changes to proxy resources in the portfolio relative to the Benchmark Case.
(1,500)
(1,000)
(500)
0
500
1,000
1,500
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
Cu
mu
lati
ve M
W
Increase/(Decrease) in Nameplate Capacity with Assumed Retirement
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas
Class 1 DSM Class 2 DSM FOT
Stacked Case C-36 Detail(NT1, JB1)
20
StudyPVRR(d) (Benefit)/Cost of 2022 Retirement
($m)
Nom. Lev. (Benefit)/Cost of 2022 Retirement per MWh of Retired Generation
($/MWh)
Cost Savings from Retired Unit
Fuel ($265) ($32.16)
Inc. Capital Rev. Req. and Fixed O&M ($461) ($55.93)
Variable O&M ($3) ($0.35)
Emissions ($122) ($14.80)
Decommissioning $9 $1.04
Total Net Cost Savings from Retired Unit ($842) ($102.20)
Net Replacement Costs
Fuel $166 $20.14
Inc. Capital Rev. Req. and Fixed O&M $354 $43.00
Variable O&M $7 $0.85
Emissions $24 $2.94
Demand-Side Management ($6) ($0.75)
Long-Term Contracts $37 $4.50
Market Purchases $50 $6.08
Market Sales $49 $5.99
Reserve/Energy Deficiencies $3 $0.31
Transmission Upgrades $0 $0.00
Transmission Reinforcements $0 $0.00
Total Net Replacement Cost $685 $83.05
Net (Benefit)/Cost of Assumed Early Retirement ($158) ($19.15)
Stacked Case C-37 Overview(NT1, JB1, HY1)
21
• No change in network transmission upgrades associated with changes to proxy resources in the portfolio relative to the Benchmark Case.
($200)
($150)
($100)
($50)
$0
$50
$100
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
$ m
illi
on
Change in System Costs (Base/Base Price-Policy)
Net (Benefit)/Cost Cumulative PVRR(d)
(1,500)
(1,000)
(500)
0
500
1,000
1,500
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
Cu
mu
lati
ve M
W
Increase/(Decrease) in Nameplate Capacity with Assumed Retirement
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas
Class 1 DSM Class 2 DSM FOT
Stacked Case C-37 Detail(NT1, JB1, HY1)
22
StudyPVRR(d) (Benefit)/Cost of 2022 Retirement
($m)
Nom. Lev. (Benefit)/Cost of 2022 Retirement per MWh of Retired Generation
($/MWh)
Cost Savings from Retired Unit
Fuel ($286) ($32.00)
Inc. Capital Rev. Req. and Fixed O&M ($492) ($55.00)
Variable O&M ($3) ($0.32)
Emissions ($131) ($14.70)
Decommissioning $9 $0.97
Total Net Cost Savings from Retired Unit ($903) ($101.06)
Net Replacement Costs
Fuel $179 $20.04
Inc. Capital Rev. Req. and Fixed O&M $415 $46.48
Variable O&M $8 $0.91
Emissions $28 $3.12
Demand-Side Management ($69) ($7.72)
Long-Term Contracts $45 $5.04
Market Purchases $58 $6.49
Market Sales $92 $10.32
Reserve/Energy Deficiencies $3 $0.38
Transmission Upgrades $0 $0.00
Transmission Reinforcements $0 $0.00
Total Net Replacement Cost $760 $85.05
Net (Benefit)/Cost of Assumed Early Retirement ($143) ($16.00)
Stacked Case C-38 Overview (NT1-2, JB1, HY1)
23
($150)
($100)
($50)
$0
$50
$100
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
$ m
illio
n
Change in System Costs (Base/Base Price-Policy)
Net (Benefit)/Cost Cumulative PVRR(d)
• No change in network transmission upgrades associated with changes to proxy resources in the portfolio relative to the Benchmark Case.
(1,500)
(1,000)
(500)
0
500
1,000
1,500
2,000
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
Cu
mu
lati
ve M
W
Increase/(Decrease) in Nameplate Capacity with Assumed Retirement
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas
Class 1 DSM Class 2 DSM FOT
Stacked Case C-38 Detail(NT1-2, JB1, HY1)
24
StudyPVRR(d) (Benefit)/Cost of 2022 Retirement
($m)
Nom. Lev. (Benefit)/Cost of 2022 Retirement per MWh of Retired Generation
($/MWh)
Cost Savings from Retired Unit
Fuel ($354) ($32.64)
Inc. Capital Rev. Req. and Fixed O&M ($599) ($55.18)
Variable O&M ($3) ($0.26)
Emissions ($152) ($13.98)
Decommissioning $13 $1.19
Total Net Cost Savings from Retired Unit ($1,096) ($100.87)
Net Replacement Costs
Fuel $257 $23.70
Inc. Capital Rev. Req. and Fixed O&M $490 $45.08
Variable O&M $21 $1.94
Emissions $37 $3.39
Demand-Side Management ($52) ($4.79)
Long-Term Contracts $49 $4.55
Market Purchases $65 $6.01
Market Sales $102 $9.38
Reserve/Energy Deficiencies $6 $0.58
Transmission Upgrades $0 $0.00
Transmission Reinforcements $0 $0.00
Total Net Replacement Cost $976 $89.84
Net (Benefit)/Cost of Assumed Early Retirement ($120) ($11.03)
Stacked Case C-39 Overview (NT1-2, JB1, HY1, CG2)
25
Change in Transmission Upgrades
Change in Year Resource Location From To ATC Max InterconnectionChange in Nominal
Capital ($m)
Accelerated from 2030 to 2029
Goshen ID Goshen ID UT North 800 800 ($5.7)
Total ($5.7)
($100)($80)($60)($40)($20)
$0$20$40$60$80
$100$120
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
$ m
illio
n
Change in System Costs (Base/Base Price-Policy)
Net (Benefit)/Cost Cumulative PVRR(d)
(2,000)
(1,000)
0
1,000
2,000
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
Cu
mu
lati
ve M
W
Increase/(Decrease) in Nameplate Capacity with Assumed Retirement
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas
Class 1 DSM Class 2 DSM FOT
Stacked Case C-39 Detail(NT1-2, JB1, HY1, CG2)
26
StudyPVRR(d) (Benefit)/Cost of 2022 Retirement
($m)
Nom. Lev. (Benefit)/Cost of 2022 Retirement per MWh of Retired Generation
($/MWh)
Cost Savings from Retired Unit
Fuel ($437) ($30.98)
Inc. Capital Rev. Req. and Fixed O&M ($683) ($48.35)
Variable O&M ($3) ($0.20)
Emissions ($197) ($13.95)
Decommissioning $13 $0.94
Total Net Cost Savings from Retired Unit ($1,306) ($92.54)
Net Replacement Costs
Fuel $203 $14.42
Inc. Capital Rev. Req. and Fixed O&M $643 $45.59
Variable O&M $15 $1.06
Emissions $17 $1.20
Demand-Side Management ($21) ($1.52)
Long-Term Contracts $64 $4.55
Market Purchases $58 $4.10
Market Sales $264 $18.67
Reserve/Energy Deficiencies $5 $0.36
Transmission Upgrades $6 $0.44
Transmission Reinforcements $0 $0.00
Total Net Replacement Cost $1,254 $88.87
Net (Benefit)/Cost of Assumed Early Retirement ($52) ($3.67)
Stacked Case C-40 Overview (NT1-2, JB1-2, HY1, CG2)
27
Change in Transmission Upgrades
Change in Year Resource Location From To ATC Max InterconnectionChange in Nominal
Capital ($m)
Accelerated from 2037 to 2028
SW WY SW WY SW WY 0 500 ($7.2)
Accelerated from 2030 to 2029
Goshen ID Goshen ID UT North 800 800 ($5.7)
Total ($12.9)
($250)
($200)
($150)
($100)
($50)
$0
$50
$100
$150
$200
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
$ m
illio
n
Change in System Costs (Base/Base Price-Policy)
Net (Benefit)/Cost Cumulative PVRR(d)
(2,000)
(1,000)
0
1,000
2,000
3,000
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
Cu
mu
lati
ve M
W
Increase/(Decrease) in Nameplate Capacity with Assumed Retirement
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas
Class 1 DSM Class 2 DSM FOT
Stacked Case C-40 Detail(NT1-2, JB1-2, HY1, CG2)
28
StudyPVRR(d) (Benefit)/Cost of 2022 Retirement
($m)
Nom. Lev. (Benefit)/Cost of 2022 Retirement per MWh of Retired Generation
($/MWh)
Cost Savings from Retired Unit
Fuel ($638) ($29.85)
Inc. Capital Rev. Req. and Fixed O&M ($1,058) ($49.51)
Variable O&M ($6) ($0.30)
Emissions ($308) ($14.43)
Decommissioning $19 $0.87
Total Net Cost Savings from Retired Unit ($1,992) ($93.23)
Net Replacement Costs
Fuel $431 $20.19
Inc. Capital Rev. Req. and Fixed O&M $845 $39.55
Variable O&M $50 $2.33
Emissions $55 $2.59
Demand-Side Management ($51) ($2.38)
Long-Term Contracts $67 $3.15
Market Purchases $93 $4.37
Market Sales $291 $13.61
Reserve/Energy Deficiencies $6 $0.26
Transmission Upgrades $13 $0.62
Transmission Reinforcements $0 $0.00
Total Net Replacement Cost $1,801 $84.29
Net (Benefit)/Cost of Assumed Early Retirement ($191) ($8.94)
Stacked Case C-41 Overview (NT1-2, JB1-2, HY1-2, CG 1-2, DJ3)
29
Change in Transmission Upgrades
Change in Year Resource Location From To ATC Max InterconnectionChange in Nominal
Capital ($m)
Accelerated from 2037 to 2028
SW WY SW WY SW WY 0 500 ($7.2)
Accelerated from 2033 to 2032
Walla Walla WA Walla Walla WA Yakima WA 200 450 ($1.7)
Total ($8.9)
(2,000)
(1,000)
0
1,000
2,000
3,000
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
Cu
mu
lati
ve M
W
Increase/(Decrease) in Nameplate Capacity with Assumed Retirement
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas
Class 1 DSM Class 2 DSM FOT
Stacked Case C-41 Detail(NT1-2, JB1-2, HY1-2, CG1-2, DJ3)
30
StudyPVRR(d) (Benefit)/Cost of 2022 Retirement
($m)
Nom. Lev. (Benefit)/Cost of 2022 Retirement per MWh of Retired Generation
($/MWh)
Cost Savings from Retired Unit
Fuel ($761) ($26.71)
Inc. Capital Rev. Req. and Fixed O&M ($1,180) ($41.43)
Variable O&M ($6) ($0.23)
Emissions ($361) ($12.66)
Decommissioning $20 $0.70
Total Net Cost Savings from Retired Unit ($2,288) ($80.33)
Net Replacement Costs
Fuel $519 $18.24
Inc. Capital Rev. Req. and Fixed O&M $1,037 $36.41
Variable O&M $47 $1.65
Emissions $52 $1.83
Demand-Side Management ($16) ($0.55)
Long-Term Contracts $77 $2.71
Market Purchases $129 $4.52
Market Sales $414 $14.53
Reserve/Energy Deficiencies $8 $0.28
Transmission Upgrades $8 $0.30
Transmission Reinforcements $0 $0.00
Total Net Replacement Cost $2,276 $79.90
Net (Benefit)/Cost of Assumed Early Retirement ($12) ($0.43)
Stacked Case C-42 Overview (NT1-2, JB1-2)
31
Change in Transmission Upgrades
($300)
($250)
($200)
($150)
($100)
($50)
$0
$50
$100
$150
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
$ m
illio
n
Change in System Costs (Base/Base Price-Policy)
Net (Benefit)/Cost Cumulative PVRR(d)
Change in Year Resource Location From To ATC Max InterconnectionChange in Nominal
Capital ($m)
Accelerated from 2037 to 2028
SW WY SW WY SW WY 0 500 ($7.2)
Total ($7.2)
(2,000)
(1,000)
0
1,000
2,000
3,000
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
Cu
mu
lati
ve M
W
Increase/(Decrease) in Nameplate Capacity with Assumed Retirement
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas
Class 1 DSM Class 2 DSM FOT
Stacked Case C-42 Detail(NT1-2, JB1-2)
32
StudyPVRR(d) (Benefit)/Cost of 2022 Retirement
($m)
Nom. Lev. (Benefit)/Cost of 2022 Retirement per MWh of Retired Generation
($/MWh)
Cost Savings from Retired Unit
Fuel ($535) ($30.65)
Inc. Capital Rev. Req. and Fixed O&M ($944) ($54.07)
Variable O&M ($6) ($0.37)
Emissions ($254) ($14.55)
Decommissioning $18 $1.04
Total Net Cost Savings from Retired Unit ($1,722) ($98.59)
Net Replacement Costs
Fuel $452 $25.88
Inc. Capital Rev. Req. and Fixed O&M $705 $40.34
Variable O&M $52 $2.96
Emissions $63 $3.60
Demand-Side Management ($26) ($1.48)
Long-Term Contracts $49 $2.78
Market Purchases $89 $5.09
Market Sales $80 $4.60
Reserve/Energy Deficiencies $4 $0.20
Transmission Upgrades $7 $0.40
Transmission Reinforcements $0 $0.00
Total Net Replacement Cost $1,474 $84.38
Net (Benefit)/Cost of Assumed Early Retirement ($248) ($14.21)
Stacked Case C-43 Overview (NT1-2, JB1, DJ3)
33
Change in Transmission Upgrades
($100)
($50)
$0
$50
$100
$150
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
$ m
illio
n
Change in System Costs (Base/Base Price-Policy)
Net (Benefit)/Cost Cumulative PVRR(d)
Change in Year Resource Location From To ATC Max InterconnectionChange in Nominal
Capital ($m)
Accelerated from 2033 to 2032
Walla Walla WA Walla Walla WA Yakima WA 200 450 ($1.7)
Total ($1.7)
(1,500)
(1,000)
(500)
0
500
1,000
1,500
2,000
20
19
20
20
20
21
20
22
20
23
20
24
20
25
20
26
20
27
20
28
20
29
20
30
20
31
20
32
20
33
20
34
20
35
20
36
20
37
20
38
Cu
mu
lati
ve M
W
Increase/(Decrease) in Nameplate Capacity with Assumed Retirement
Coal Removed Wind Solar Wind+Bat
Solar+Bat Battery Pumped Storage Gas
Class 1 DSM Class 2 DSM FOT
Stacked Case C-43 Detail(NT1-2, JB1, DJ3)
34
StudyPVRR(d) (Benefit)/Cost of 2022 Retirement
($m)
Nom. Lev. (Benefit)/Cost of 2022 Retirement per MWh of Retired Generation
($/MWh)
Cost Savings from Retired Unit
Fuel ($411) ($26.48)
Inc. Capital Rev. Req. and Fixed O&M ($640) ($41.30)
Variable O&M ($3) ($0.18)
Emissions ($183) ($11.82)
Decommissioning $14 $0.91
Total Net Cost Savings from Retired Unit ($1,223) ($78.87)
Net Replacement Costs
Fuel $352 $22.72
Inc. Capital Rev. Req. and Fixed O&M $572 $36.91
Variable O&M $27 $1.71
Emissions $51 $3.32
Demand-Side Management $3 $0.19
Long-Term Contracts $36 $2.32
Market Purchases $74 $4.76
Market Sales $70 $4.53
Reserve/Energy Deficiencies $5 $0.33
Transmission Upgrades $2 $0.10
Transmission Reinforcements $0 $0.00
Total Net Replacement Cost $1,193 $76.90
Net (Benefit)/Cost of Assumed Early Retirement ($31) ($1.97)
Reliability Assessment
35
Incremental Capacity from Deterministic Analyses
36
• Hourly, deterministic reliability assessment for 2023, 2030, and 2038 for each case.
• Deterministic studies reflect “perfect foresight” for the following assumptions:
• Normal load (1-in-2 exceedance)
• Average thermal outages in all hours
• Average hydro conditions
• Fixed variable energy resource generation profiles, and
• Average market prices without electric or natural gas price volatility and physical supply risks
• Additional flexible capacity is required beyond the capacity needed to “cure” hourly shortfalls to reliably serve customers considering that the above factors vary from day to day and hour to hour and are not known in advance.
Variable Energy Resource Uncertainty
37
• Variable energy resources are modeled with fixed hourly generation profiles and always produce as scheduled in the model, however, in reality, there is significant uncertainty on a day-ahead, hour-ahead and real-time basis.
• The estimated total day-ahead reserve requirement, including day-ahead uncertainty for load, wind, and solar, as a percentage of load:
• 2018 historical: carried average reserves amounting to 18% of load.
• 2023 forecast: will need average reserves at 19% of load.
• These values are higher than the current planning reserve margin.
• Short-term solutions:
• Larger firm market purchases.
• More thermal unit commitment and fuel nominations.
• Long-term solutions:
• Incremental flexible capacity additions.
Market Supply Uncertainty
38
Net Capacity Additions/Retirements, excluding Wind and Solar
Source: Energy Information Administration Form 860. 2015-2025.
Market Supply Uncertainty
39
• Potential PacifiCorp retirements are not included.
• Recent events have highlighted natural gas pipeline delivery risk.
• Additional flexible capacity is required to address this market supply uncertainty.
Source: Energy Information Administration Form 860.
Calculating the Capacity Need from Deterministic Analyses
40
• Portfolios must meet four hourly requirements: • Energy, non-spinning reserve, spinning reserve, and regulation reserve
• Separate requirements for East and West, but transfers allowed up to transmission limits.
• Shortfall or unused available capacity is calculated for each hour.• Maximum hourly shortfall (or minimum available) is identified by season.
• Given aforementioned risk factors, 500 MW of capacity in excess of hourly shortfalls identified in the deterministic studies was required.
• Allocated between East and West based on peak load by season:• Example 1: 200 MW required – 100 MW available = 100 MW incremental
• Example 2: 200 MW required + 50 MW shortfall = 250 MW incremental• Incremental requirements applied: 2023-2027 based on the 2023 deterministic
study, 2028-2036 based on the 2030 deterministic study, and 2037-2038 based on the 2038 deterministic study.
• The SO model adds or accelerates the following resource types relative to the pre-reliability portfolio to meet East and West incremental requirements:
• Batteries, Energy Efficiency, Gas Peakers, Pumped Storage• Other resource types are locked at levels in pre-reliability portfolio.
Reliability Resources
41
Reliability Resources (Continued)
42
Reliability Resources (Continued)
43
Stakeholder Feedback Form Recap
44
2019 IRP vs. 2017 IRP Stakeholder Feedback Form Activity to Date
45
0
20
40
60
80
100
120
140
160
180
July-Aug Sept-Oct Nov-Dec Jan-Feb Mar-Apr
2017 Forms 2017 Questions 2019 Forms (to date) 2019 Questions (to date)
Stakeholder Feedback Forms
46
• 85 stakeholder feedback forms submitted to date.
• Stakeholder feedback forms and responses can be located at: www.pacificorp.com/es/irp/irpcomments.html.
• Depending on the type and complexity of the stakeholder feedback received responses may be provided in a variety of ways including, but not limited to, a written response, a follow-up conversation, or incorporation into subsequent public input meeting material.
• Stakeholder feedback following the most recent public input meeting is summarized on the following slides for reference.
Summary - Recent Stakeholder Feedback Forms
47
Stakeholder Date Topic Brief Summary (complete form available online) Response (posted onlinewhen available)
WUTC Mar 22 General Feedback and questions from March public input meeting.
Target response week of April 29.
UCE Mar 22 Private Generation
Request for clarification and explanation on inputs regarding Navigant’s 2018 Private Generation Long-Term Resource Assessment.
Provided clarification and explanation on data inputs.
UCE Apr 3 DSM Modeling
Request for additional DSM modeling. Target response week of April 29.
UCE Apr 4 Coal Analysis Request for CO2 price data inputs, explanation of calculation of decommissioning costs, and specific unit and contract information.
Target response week of April 29.
Additional Information and Next Steps
48
Draft Topics for Upcoming PIMs*
49
May 20-21, 2019 PIM*
• Regional Haze Cases
• Portfolio Development Cases
• Stakeholder Feedback Form Recap
June-July, 2019*
• Portfolio Development Cases
• Sensitivity Studies
• Portfolio Selection Process
• Draft Preferred Portfolio
• Draft Action Plan
• Stakeholder Feedback Form Recap
* Topics and timing are tentative and subject to change
Additional Information and Next Steps
50
• Public Input Meeting Presentation and Materials:
• pacificorp.com/es/irp.html
• 2019 IRP Stakeholder Feedback Forms:
• pacificorp.com/es/irp/irpcomments.html
• IRP Email / Distribution List Contact Information:
• Upcoming Public Input Meeting Dates:
• May 20-21, 2019
• June 20-21, 2019
• July 18-19, 2019 (as needed)
• August 1, 2019 – 2019 IRP File Date